It has long been known that only a portion of the total crude oil present in a reservoir can be recovered during a primary recovery process, this primary process resulting in oil being recovered under the natural energy of the reservoir. The reservoir typically takes the form of an oil-bearing subterranean rock formation having sufficient porosity and permeability to store and transmit fluids, and with which oil is associated, for example being held in pores or between grains of the rock formation. So-called secondary recovery techniques are used to force additional oil out of the reservoir, the simplest method of which is by direct replacement with another medium in the form of an injected fluid, usually water or gas. Enhanced oil recovery (EOR) techniques can also be used. The purpose of such EOR techniques is not only to restore or maintain reservoir pressure, but also to improve oil displacement in the reservoir, thereby minimising the residual oil saturation of the reservoir, that is, the volume of oil present in the reservoir.
“Waterflooding” is one of the most successful and extensively used secondary recovery methods. Water is injected, under pressure, into reservoir rock formations via injection wells. The injected water acts to help maintain reservoir pressure, and sweeps the displaced oil ahead of it through the rock towards production wells from which the oil is recovered. The water used in waterflooding is generally saline water from a natural source such as seawater or may be produced water (i.e. water that is separated from the crude oil at a production facility).
The impact of waterfloods and EOR techniques in oil reservoirs and oil fields can be monitored, and oil field operations can be managed, by acquiring data relating to selected characteristics and/or parameters of the reservoir and employing computer-implemented reservoir models to analyse the data. Interpreting and understanding the dynamics of reservoir waterflooding is of great value. Reservoirs can include complex geological layering of many rock formations, each having different properties, which can influence the flow pattern of fluid (including oil and/or injection fluid) in different ways.
In many situations, injection fluid injected during a waterflood may find a “short-circuiting” path from an injection well to a production well along high permeability pathways within the reservoir, thereby bypassing much of the oil present in the rock formation(s) of the reservoir. In order to mitigate the impact of such effects and improve the efficiency of oil recovery, polymers may be added to the waterflood injection fluid; when they mix with the water, the polymers may act as viscosifiers for the injection fluid thereby effectively partially or fully blocking the high permeability pathways and reducing the permeability of the rock locally, leading to an enhancement of the flow in the lower permeability zones, and again improving the amount of oil recovered. As disclosed in U.S. Pat. No. 7,300,973, it is also known to add polymeric microparticles to the injection fluid wherein the microparticles have labile (reversible) and non-labile internal cross links in which the microparticle conformation is constrained by the labile internal cross links. The microparticle properties, such as particle size distribution and density, of the constrained microparticle are designed to allow efficient propagation through the pore structure of hydrocarbon reservoir matrix rock. On heating to reservoir temperature and/or at a predetermined pH, the labile internal cross links start to break allowing the particle to expand by absorbing the injection fluid (normally water). The expanded particle is engineered to have a particle size distribution and physical characteristics, for example, particle rheology, which allow it to impede the flow of injected fluid in the pore structure. In doing so it is capable of diverting chase fluid into less thoroughly swept zones of the reservoir. By using either of these techniques, zones of high permeability may be blocked off deep within the reservoir, and in theory this will enable greater sweep, and hence recovery, of oil in the originally less permeable zones of the reservoir. However, the increase in viscosity of the injection fluid or the presence of polymeric particles in the injection fluid can lead to increased difficulty in injecting fluid into the reservoir rock.
It is also known to add surfactants to the waterflood injection fluid to enhance the release of oil from the surface of the rock formation by changing the wettability of the rock to the oil. Surfactants also act by emulsifying or de-emulsifying the oil.
Microbial Enhanced Oil Recovery (MEOR) techniques can also be employed to increase the amount of oil extracted from a reservoir (thereby decreasing the residual oil saturation of the reservoir rock). Microbes, and associated nutrients which feed the microbes to encourage microbial population growth, are added to an injection water and are therefore injected into the reservoir. The resulting microbial activity within the reservoir can increase oil production by a number of mechanisms, including:                (a) generation of biomass (biofilms) that result in selective blocking, and therefore a reduction in the permeability of, high permeability pathways to encourage the waterflood to sweep the originally less permeable pathways of the reservoir. Biofilms may also alter wettability of the reservoir rock to oil thereby resulting in release of adhering oil from the reservoir rock;        (b) the generation of biosurfactants that can change the oil wettability of the reservoir rock or can result in emulsification or de-emulsification of the oil and reduce interfacial tension;        (c) the generation of biopolymers that can change the injectivity profile and/or result in viscosity modification of the injected fluid thereby resulting in selective plugging of high permeability pathways in the reservoir;        (d) the generation of organic acids (for example, propionic and butyric acids) that can dissolve reservoir rock thereby increasing its permeability and can also result in the generation of surfactants by the interaction of the organic acids with metal salts that are present in the injection water or connate water;        (e) the generation of solvents (acetone, butanol, propan-2-ol) that can result in a decrease in oil viscosity;        (f) the generation of gases (hydrogen, carbon dioxide, or methane) that can result in an increase in reservoir pressure, oil swelling, or a reduction in interfacial tension and viscosity; and        (g) the microbes can promote biodegradation of heavy oils into lighter oils.        
MEOR is advantageous in that it is relatively inexpensive, environmentally friendly and technically relatively simple to apply; however, it can involve complex mechanisms which are difficult to monitor and assess.
Currently, laboratory coreflood testing (where a sample of rock is removed from a reservoir rock formation, before oil production begins or during primary recovery, and is then placed under the reservoir conditions for testing in the laboratory) can be applied in order to determine the residual oil saturation of the formation following a waterflood. Single coreflood experiments are well known in the crude oil recovery industry and are analysed in order to give an indication of the effect of reservoir treatments at the laboratory scale.